Heterogeneous proppant placement in a fracture with removable channelant fill

ABSTRACT

A method of heterogeneous proppant placement in a subterranean fracture is disclosed. The method comprises injecting well treatment fluid including proppant ( 16 ) wherein the proppant comprises from 1 to 100 percent in weight of stiff, low-elasticity and low-deformability elongated particles ( 34 ) and proppant-spacing filler material called a channelant ( 18 ) through a wellbore ( 10 ) into the fracture ( 20 ), heterogeneously placing the proppant in the fracture in a plurality of proppant clusters or islands ( 22 ) spaced apart by the channelant ( 24 ), and removing the channelant filler material ( 24 ) to form open channels ( 26 ) around the pillars ( 28 ) for fluid flow from the formation ( 14 ) through the fracture ( 20 ) toward the wellbore ( 10 ). The proppant and channelant can be segregated within the well treatment fluid, or segregated during placement in the fracture. The channelant can be dissolvable particles, initially acting as a filler material during placement of the proppant in the fracture, and later dissolving to leave the flow channels between the proppant pillars. The well treatment fluid can include fibers to provide reinforcement and consolidation of the proppant and, additionally or alternatively, to inhibit settling of the proppant in the treatment fluid.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part application of applicationSer. No. 12/507,558, entitled “HETEROGENEOUS PROPPANT PLACEMENT IN AFRACTURE WITH REMOVABLE CHANNELANT FILL” filed on Jul. 22, 2009, whichis a divisional application of application Ser. No. 11/608,686, now U.S.Pat. No. 7,581,590, entitled “HETEROGENEOUS PROPPANT PLACEMENT IN AFRACTURE WITH REMOVABLE CHANNELANT FILL” filed on Dec. 8, 2006 and is acontinuation-in-part application of application Ser. No. 11/768,393,entitled “PROPPANT MATERIAL AND FORMATION HYDRAULIC FRACTURING METHOD”filed on Jun. 26, 2007, which are all hereby in their entiretyincorporated by reference.

FIELD OF THE INVENTION

The invention relates to stimulation of wells penetrating subterraneanformations, to fracture stimulation by injection of proppant into afracture to form regions of low resistance to flow through the fracturefor the production of hydrocarbons and in some cases by usingnon-spherical proppant.

BACKGROUND

Various methods are known for fracturing a subterranean formation toenhance the production of fluids therefrom. In the typical application,a pressurized fracturing fluid hydraulically creates and propagates afracture. The fracturing fluid carries proppant particulates into theextending fracture. When the fracturing fluid is removed, the fracturedoes not completely close from the loss of hydraulic pressure; instead,the fracture remains propped open by the packed proppant, allowingfluids to flow from the formation through the proppant pack to theproduction wellbore.

The success of the fracturing treatment may depend on the ability offluids to flow from the formation through the proppant pack. In otherwords, the proppant pack or matrix must have a high permeabilityrelative to the formation for fluid to flow with low resistance to thewellbore. Furthermore, the surface regions of the fracture should not besignificantly damaged by the fracturing to retain fluid permeability foroptimal flow from the formation into the fracture and the proppant pack.

The prior art has sought to increase the permeability of the proppantpack by increasing the porosity of the interstitial channels betweenadjacent proppant particles within the proppant matrix. For example,US200600408944A1 (van Batenburg, et al.) incorporated herewith byreference discloses a method of forming a high porosity propped fracturewith a slurry that includes a fracturing fluid, proppant particulatesand a weighting agent. These prior art technologies seek to distributethe porosity and interstitial flow passages as uniformly as possible inthe consolidated proppant matrix filling the fracture, and thus employhomogeneous proppant placement procedures to substantially uniformlydistribute the proppant and non-proppant, porosity-inducing materialswithin the fracture.

As another example, in US20060048943A1 (Parker, et al.) incorporatedherewith by reference proppant particulates and degradable material donot segregate before, during or after injection to help maintainuniformity within the proppant matrix. Fracturing fluids are thoroughlymixed to prevent any segregation of proppant and non-proppantparticulates. In another approach, non-proppant materials have a size,shape and specific gravity similar to that of the proppant to maintainsubstantial uniformity within the mixture of particles in the fracturingfluid and within the resulting proppant pack. A tackifying compoundcoating on the particulates has also been used to enhance the homogenousdistribution of proppant and non-proppant particulates as they areblended and pumped downhole into a fracture.

A recent approach to improving hydraulic fracture conductivity has beento try to construct proppant clusters in the fracture, as opposed toconstructing a continuous proppant pack. US6,776,235 (England)incorporated herewith by reference discloses a method for hydraulicallyfracturing a subterranean formation involving alternating stages ofproppant-containing hydraulic fracturing fluids contrasting in theirproppant-settling rates to form proppant clusters as posts that preventfracture closing. This method alternates the stages of proppant-ladenand proppant-free fracturing fluids to create proppant clusters, orislands, in the fracture and channels between them for formation fluidsto flow. The amount of proppant deposited in the fracture during eachstage is modulated by varying the fluid transport characteristics (suchas viscosity and elasticity), the proppant densities, diameters, andconcentrations and the fracturing fluid injection rate. However, thepositioning of the proppant-containing fluid is difficult to control.For example, the proppant-containing fluid can have a higher densitythan the proppant-free fluid and can thus underride the proppant-freefluid. This underride can result in non-uniform distribution of proppantclusters, which in turn can lead to excessive fracture closure wherethere is not enough proppant and constricted flow channels where thereis too much proppant.

On the other way, many materials have been included in proppant packs toenhance the conductivity. U.S. Pat. No. 5,330,005 incorporated herewithby reference disclosed adding fibers made for example of glass, ceramic,carbon, natural or synthetic polymers or metal. They have a length of upto about 30 mm and a diameter of between 6 and 100 microns. According toU.S. Pat. No. 5,908,073 incorporated herewith by reference flowback isprevented through the use of fibrous bundles, made of from about 5 toabout 200 individual fibers having lengths in the range of about 0.8 toabout 2.5 mm and diameters in the range of about 10 to about 1000microns. U. S. Pat. No. 6,059,034 incorporated herewith by referencedisclosed blending proppant material with a deformable particulatematerial such as polystyrene divinylbenzene beads. They definedeformable materials as having a Young's modulus between about 0.00345and about 13.8 GPa. The deformable particles may have different shapessuch as oval, cubic, bar-shaped, cylindrical, multi-faceted, irregular,and tapered, but they preferably have a maximum length-based aspectratio equal to or less than 5, and are typically spherical plastic beadsor composite particles comprising a non-deformable core and a deformablecoating. U.S. Pat. No. 6,330,916 incorporated herewith by reference alsodescribes the use of deformable materials having a maximum length-basedaspect ratio of equal to or less than about 25 and a Young's modulus ofbetween about 500 psi (about 0.0034 GPa) and about 2,000,000 psi (about13.79 GPa) under formation conditions. U. S. Pat. No. 6,725,930incorporated herewith by reference describes the use of metallic wireshaving an aspect ratio of greater than 5 and making use of theproperties of the metals.

More recently approach was made to increase proppant pack conductivityby using non-spherical proppant. International application WO2009/088317 incorporated herewith by reference discloses a method offracturing with a slurry of proppant containing from 1 to 100 percent ofstiff, low elasticity, low deformability elongated particles. US patentapplication 2007/768393 incorporated herewith by reference disclosesproppant that is in the form of generally rigid, elastic plate-likeparticles having a maximum to minimum dimension ratio of more than about5, the proppant being at least one of formed from a corrosion resistantmaterial or having a corrosion resistant material formed thereon.

It is an object of the present invention to provide a new type ofproppant and improved methods of propping a fracture, or a part of afracture.

SUMMARY

According some embodiments, a fracturing treatment includes theinjection of both proppant and a removable material that can act as fillto physically separate the proppant clusters at appropriate distancesduring placement in the fracture, but can subsequently be removed toform channels. The proppant comprises from 1 to 100 percent in weight ofstiff, low-elasticity and low-deformability elongated particles. Theproppant and removable material are disposed within a fracture in such away that the removable material is segregated from the proppant to actas a temporary filler material compressed in the fracture in spacesbetween clusters or islands of proppant which form pillars to hold openthe fracture. Then, the fill material is removed to form open channelsfor unimpeded fluid flow through the fracture in the spaces left aroundthe proppant pillars. Applicant refers herein to the removable,channel-forming fill material as “channelant.”

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically illustrates in section placement of proppant andremovable channelant in a hydraulic fracture operation according to anembodiment of the invention.

FIG. 2 schematically illustrates in section the arrangement of thewellbore, perforations and the proppant pillars in the fracturefollowing removal of the channelant from the fracture of FIG. 1.

FIG. 3 schematically illustrates the wall effect introduced by use ofelongated particles.

DETAILED DESCRIPTION

At the outset, it should be noted that in the development of any suchactual embodiment, numerous implementation—specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem related and business related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure.

The description and examples are presented solely for the purpose ofillustrating the preferred embodiments of the invention and should notbe construed as a limitation to the scope and applicability of theinvention. While the compositions of the present invention are describedherein as comprising certain materials, it should be understood that thecomposition could optionally comprise two or more chemically differentmaterials. In addition, the composition can also comprise somecomponents other than the ones already cited. In the summary of theinvention and this detailed description, each numerical value should beread once as modified by the term “about” (unless already expressly somodified), and then read again as not so modified unless otherwiseindicated in context. Also, in the summary and this detaileddescription, it should be understood that a concentration range listedor described as being useful, suitable, or the like, is intended thatany and every concentration within the range, including the end points,is to be considered as having been stated. For example, “a range of from1 to 10” is to be read as indicating each and every possible numberalong the continuum between about 1 and about 10. Thus, even if specificdata points within the range, or even no data points within the range,are explicitly identified or refer to only a few specific, it is to beunderstood that inventors appreciate and understand that any and alldata points within the range are to be considered to have beenspecified, and that inventors possession of the entire range and allpoints within the range.

Fracturing fluids according to the present method can include proppantand a removable proppant-spacing material, which can function to formopen channels around the proppant pillars. These extramatricalchannel-forming materials, including proppant-spacing particles, arereferred to herein as “channelant.”

As used herein, the term “open channels” refers to interconnectedpassageways formed in the proppant-fracture structure. Open channels aredistinct from interstitial passages between individual proppantparticles in the proppant matrix in that the channels fully extendbetween opposing fracture faces, free of obstruction by proppant orother flow-impeding structures, and exist outside the proppant matrix,laterally bounded by the proppant pillars. Such open channels generallyhave a hydraulic radius, and hence a hydraulic conductivity, that is atleast an order of magnitude larger than that of interstitial flowpassages through the proppant matrix.

The open channels can be formed by placing the proppant and channelantin the fracture in such a way that the pillar-forming proppant islandsare ultimately segregated from the channel-forming removable material.The segregation can occur or begin in the preparation, mixing or pumpingof the treatment fluid, in the injection of the treatment fluid in thefracture, in or after the proppant placement, packing or settling in thefracture, by a distinct post-injection step of chemical and/ormechanical manipulation or treatment of the proppant/channelantfollowing initial placement in the fracture, or by aggregating andconsolidating the proppant during the channelant removal.

As used herein, the terms “segregation,” “segregating” and the likerefer to any heterogeneous proppant/channelant distribution betweenproppant-rich pillar-forming islands or regions and proppant-leanchannelant regions. It may not be necessary to keep the proppant-richregions entirely free of channelant because the presence of channelant,especially in relatively minor amounts, may not exceed any level thatprevents the formation or consolidation of the proppant into pillars ofsufficient strength to prevent the fracture from closing. In anembodiment, the channelant can function in the proppant or proppantregions to consolidate or reinforce the proppant islands and/or tostrengthen the proppant pillars. Conversely, the channelant regions cancontain proppant particles, especially relatively minor amounts, whichremain unconsolidated or do not otherwise prevent removal of thechannelant to form the open channels and which do not result inobstruction or excessive clogging of the open channels by the proppant.

A simplified embodiment of the method is illustrated with reference toFIGS. 1 and 2, in which the channelant particles can be generallyinsoluble in the injection fluid and soluble in the formation fluid. InFIG. 1, a wellbore 10 can be completed with perforations 12 in formation14. Segregated proppant particles 16 and channelant particles 18 can beinjected in a fracturing fluid through the wellbore 10 into a fracture20, where they can be heterogeneously placed in respective proppant-richislands 22 spaced apart by channelant-rich regions 24. The fracture 20can be allowed to close, and the proppant blend islands 22 compressed toform pillars to support the fracture 20 and prevent the opposingfracture faces from contacting each other. Simultaneously, thechannelant can be packed in the proppant-lean regions 24 and can helprestrict the islands 22 from creeping or spreading laterally due tocompression by the weight of the formation, thereby facilitating agreater height or open dimension of the resulting propped fracture and agreater hydraulic conductivity.

During the next operative step, the channelant can be removed in variousembodiments by flushing, dissolving, softening, melting, breaking, ordegrading the channelant, wholly or partially, via a suitable activationmechanism, such as, but not limited to, temperature, time, pH, salinity,solvent introduction, catalyst introduction, hydrolysis, and the like,or any combination thereof. The activation mechanism can be triggered byambient conditions in the formation, by the invasion of formationfluids, exposure to water, passage of time, by the presence of incipientor delayed reactants in or mixed with the channelant particles, by thepost-injection introduction of an activating fluid, or the like, or anycombination of these triggers.

Then, with reference to FIG. 2, the formation fluid can be allowed toinvade the fracture 20 to displace any channelant, channelant solution,channelant degradation products, and any unconsolidated proppant orother particles, from the proppant-lean regions. In one embodiment, thechannelant can simply be unconsolidated so that it can be removedhydraulically, or can include unconsolidated particles that can beremoved hydraulically, e.g. by flushing the fracture with formationfluid and/or an injected flushing or back-flushing fluid. A network ofinterconnected open channels 26 can thus be formed around the pillars 28to provide the fracture 20 with high conductivity for fluid flow. Fluidscan now be produced from the formation 14, into the fracture 20, throughthe open channels 26 and perforations 12, and into the wellbore 10.

The channelant can be removed mechanically, for example by using fluidto push channelant out of the formation. In such instances, thechannelant can remain in a solid state from the time of injectionthrough removal from the fracture. Some suitable materials that canresist degradation and crushing include glass, ceramics, carbon andcarbon-based compounds, metals and metallic alloys, and high-densityplastics that are oil-resistant and exhibit a crystallinity of greaterthan about 10%. Some other suitable high density plastic materialsinclude nylons, acrylics, styrenes, polyesters, polyethylenes,oil-resistant thermoset resins and combinations thereof.

Alternatively, the channelant can be softened, dissolved, reacted orotherwise made to degrade. Materials suitable for dissolvable channelantinclude for example, and without limitation, polyvinyl alcohol (PVOH)fibers, salt, wax, calcium carbonate, and the like and combinationsthereof. An oil-degradable channelant can be selected, so that it willbe degraded by produced fluids. Alternatively, a channelant can beselected which is degraded by agents purposefully placed in theformation by injection, wherein mixing the channelant with the agentinduces a delayed reaction degradation of the channelant.

In some fracturing operations, a solid acid-precursor can be used as thedegradable channelant. Suitable acid-generating dissolvable channelantscan include for example, and without limitation, PLA, PGA, carboxylicacid, lactide, glycolide, copolymers of PLA or PGA, and the like andcombinations thereof. Provided that the formation rock is carbonate,dolomite, sandstone, or otherwise acid reactive, then the hydrolyzedproduct of the channelant, a reactive liquid acid, can etch theformation at surfaces exposed between the proppant pillars. This etchingcan enlarge the open channels and thus further enhance the conductivitybetween the pillars. Other uses of the generated acid fluid can includeaiding in the breaking of residual gel, facilitating consolidation ofproppant clusters, curing or softening resin coatings and increasingproppant permeability.

In some embodiments, the channelant may be formed of, or contain, afluoride source capable of generating hydrofluoric acid upon release offluorine and adequate protonation. Some nonlimiting examples of fluoridesources which are effective for generating hydrofluoric acid includefluoboric acid, ammonium fluoride, ammonium fluoride, and the like, orany mixtures thereof.

During hydraulic fracturing, high pressure pumps on the surface injectthe fracturing fluid into a wellbore adjacent to the face or pay zone ofa geologic formation. The first stage, also referred to as the “padstage” involves injecting a fracturing fluid into a borehole at asufficiently high flow rate and pressure sufficient to literally breakor fracture a portion of surrounding strata at the sand face. The padstage is pumped until the fracture has sufficient dimensions toaccommodate the subsequent slurry pumped in the proppant stage. Thevolume of the pad can be designed by those knowledgeable in the art offracture design, for example, as described in Reservoir Stimulation, 3rdEd., M. J. Economides, K. G. Nolte, Editors, John Wiley and Sons, NewYork, 2000, incorporated herewith by reference.

Water-based fracturing fluids are common, with natural or syntheticwater-soluble polymers optionally added to increase fluid viscosity, andcan be used throughout the pad and subsequent proppant and/or channelantstages. These polymers include, but are not limited to, guar gums;high-molecular-weight polysaccharides composed of mannose and galactosesugars; or guar derivatives, such as hydroxypropyl guar, carboxymethylguar, carboxymethylhydroxypropyl guar, and the like. Cross-linkingagents based on boron, titanium, zirconium or aluminum complexes aretypically used to increase the effective molecular weight of the polymerfor use in high-temperature wells. To a small extent, cellulosederivatives, such as hydroxyethylcellulose or hydroxypropylcellulose andcarboxymethylhydroxyethylcellulose, are used with or withoutcross-linkers. Two biopolymers—xanthan and scleroglucan—provideexcellent proppant suspension, but are more expensive than guarderivatives and so are used less frequently. Polyacrylamide andpolyacrylate polymers and copolymers are typically used forhigh-temperature applications or as friction reducers at lowconcentrations for all temperatures ranges. Polymer-free, water-basefracturing fluids can also be obtained using viscoelastic surfactants.Usually, these fluids are prepared by mixing in appropriate amounts ofsuitable surfactants, such as anionic, cationic, nonionic, amphoteric,and zwiterionic. The viscosity of viscoelastic surfactant fluids areattributed to the three-dimensional structure formed by the fluid'scomponents. When the surfactant concentration in a viscoelastic fluidsignificantly exceeds a critical concentration, and in most cases in thepresence of an electrolyte, surfactant molecules aggregate into species,such as worm-like or rod-like micelles, which can interact to form anetwork exhibiting viscous and elastic behavior.

After the fracture is induced, proppant and channelant can be injectedinto the fracture as a slurry or suspension of particles in thefracturing fluid during what is referred to herein as the “proppantstage.” In the proppant stage, proppant and channelant can be injectedin one or more segregated substages alternated between a “proppantsubstage” and a “channelant substage,” and/or as a mixture of channelantand proppant in one or more substages referred to herein as a “mixedsubstage.” Further, the proppant, channelant and/or mixed substages canbe separated by one or more optional “carrier substages”, which aresubstantially free of proppant and channelant and can also besubstantially free of other particles.

As a result, the proppant does not completely fill the fracture. Rather,spaced proppant clusters form as pillars with proppant-spacingchannelant material initially filling the channels between them, throughwhich, upon subsequent removal of the channelant, formation fluids pass.The volumes of proppant, channelant and carrier sub-stages as pumped canbe different. That is, the volume of the channelant and any carriersubstages can be larger or smaller than the volume of the proppantand/or any mixed substages. Furthermore, the volumes and order ofinjection of these substages can change over the duration of theproppant stage. That is, proppant substages pumped early in thetreatment can be of a smaller volume then a proppant substage pumpedlater in the treatment. The relative volume of the substages can beselected by the engineer based on how much of the surface area of thefracture it is desired to be supported by the clusters of proppant, andhow much of the fracture area is desired as open channels through whichformation fluids are free to flow.

Suitable proppants can include sand, gravel, glass beads, ceramics,bauxites, glass, and the like or combinations thereof. Also otherproppants like, plastic beads such as styrene divinylbenzene, andparticulate metals may be used. Proppant used in this application maynot necessarily require the same permeability properties as typicallyrequired in conventional treatments because the overall fracturepermeability will at least partially develop from formation of channels.Other proppants may be materials such as drill cuttings that arecirculated out of the well. Also, naturally occurring particulatematerials may be used as proppants, including, but are not necessarilylimited to: ground or crushed shells of nuts such as walnut, coconut,pecan, almond, ivory nut, brazil nut, etc.; ground or crushed seedshells (including fruit pits) of seeds of fruits such as plum, olive,peach, cherry, apricot, etc.; ground or crushed seed shells of otherplants such as maize (e.g., corn cobs or corn kernels), etc.; processedwood materials such as those derived from woods such as oak, hickory,walnut, poplar, mahogany, etc., including such woods that have beenprocessed by grinding, chipping, or other form of particalization,processing, etc, some nonlimiting examples of which are proppants madeof walnut hulls impregnated and encapsulated with resins. Furtherinformation on some of the above-noted compositions thereof may be foundin Encyclopedia of Chemical Technology, Edited by Raymond E. Kirk andDonald F. Othmer, Third Edition, John Wiley & Sons, Volume 16, pages248-273 (entitled “Nuts”), Copyright 1981, which is incorporated hereinby reference. Resin coated (various resin and plastic coatings) orencapsulated proppants having a base of any of the previously listedpropping materials such as sand, ceramics, bauxite, nut shells, etc. maybe used in accordance with the invention. Essentially, the proppant canbe any material that will hold open the propped portion of the fracture.

The selection of proppant can balance the factors of proppant long-termstrength, proppant distribution characteristics and proppant cost. Theproppant can have the ability to flow deeply into the hydraulic fractureand form spaced pillars that resist crushing upon being subjected to thefracture closure stress. Relatively inexpensive, low-strength materials,such as sand, can be used for hydraulic fracturing of formations withsmall internal stresses. Materials of greater cost, such as ceramics,bauxites and others, can be used in formations with higher internalstresses. Further, the chemical interaction between produced fluids andproppants, which can significantly change the characteristics of theproppant, can be considered.

Because one embodiment may not rely on the porosity or permeability ofthe packed proppant matrix to impart flow conductivity to the fracture,the availability of the option to select a wider range of proppantmaterials can be an advantage of the present embodiments. For example,proppant can have any size or range of mixed, variable diameters orother properties that yield a high-density, high-strength pillar, whichcan form a proppant matrix that has high or low porosity and high or lowpermeability—proppant porosity and permeability are not so important inan embodiment—because fluid production through the proppant matrix isnot required. Also, an adhesive or reinforcing material that would pluga conventional proppant pack can be employed in the interstitial spacesof the proppant matrix herein, such as, for example, a settable orcrosslinkable polymer which can be set or crosslinked in the proppant.Thus, a proppant pillar of suitable strength can be successfully createdusing sand with particles too weak for use in conventional hydraulicfracturing. Sand costs substantially less than ceramic proppant.Additionally, destruction of sand particles during application of thefracture closure load can improve strength behavior of the same clusterconsisting of proppant granules. This can occur because thecracking/destruction of proppant particles decreases the clusterporosity thereby compacting the proppant. Sand pumped into the fractureto create proppant clusters does not need good granulometric properties,that is, the narrow particle size or diameter distribution required fora permeable proppant pack in conventional fracturing. For example, inone embodiment, it is possible to use 50 tons of sand, wherein 10 to 15tons have a diameter of particles from 0.002 to 0.1 mm, 15 to 30 tonshave a diameter of particles from 0.2 to 0.6 mm, and 10 to 15 tons havea diameter of particles from 0.005 to 0.05 mm. It should be noted thatconventional hydraulic fracturing would require about 100 tons of aproppant more expensive than sand to obtain a similar value of hydraulicconductivity for fluid passage through the continuous-porosity proppantmatrix in the propped fracture.

The proppant blend can include elongated proppants. An importantparameter for suitable materials for elongated proppant is a suitablematerial deformability, the ability of a material to deform withoutbreaking (failure) under the action of load. Material deformability maybe measured as the degree of deformation in a large number of tests, forexample tension, compression, torsion, bending etc. In some cases, theloading force is applied in such a way that uniform deformation issustained, and the direction of the applied force does not change duringthe entire process of loading (the geometrically linear case). Also avery important property of the elongated proppant particles is thecurvature.

An important effect of using elongated particles is a porosity increase.It is a well-known fact in chemical engineering that in the near wallregion of a reactor having a packed bed of spherical particles a wallregion having higher conductivity is observed. This region extends intothe packed bed about 2-3 particle diameters. Due to this effect, thevelocity profile of fluids flowing through the bed is non-uniform andthere is a higher flow velocity near the reactor wall. Not to be limitedby theory, but it is believed that the elongated particles takeadvantage of this “wall effect” to improve the permeability andconductivity of proppant, sand, and/or gravel packs by addingnon-deformable, elongated (or High Aspect Ratio Particles (HARP))particles to the packed bed. The elongated particles have the effect ofadding additional surface that is, creating additional “walls” in thepacked bed. This effect is shown in FIG. 3, in which (a) shows theconventional tortuous flow path 30 of a fluid through packed spheres ofconventional proppant particles 16, and (b) shows a region of straightflow 31 of fluid along the interface of an elongated particle 34 and thepacked spheres of conventional proppant particles 16. However, for mostmaterials there is an aspect ratio above which an elongated particle maybend. Generally, in the literature the term “fiber” is used for verylong materials that can bend extensively without breaking The term“fiber” may be used for elongated particles suitable for the proppantblends provided that it is understood that suitable particles should notbend or deform substantially or break in use.

Some useful shapes of elongated particles are rods, ovals, plates anddisks. The shapes of the elongated particles need not necessarily fitinto any of these categories, i.e. the elongated particles may haveirregular shapes. While described are elongated particles such as rodsor elongated rods, any elongated shape, for example rods, ovals, platesand disks may be useful. The maximum length-based aspect ratio of theindividual elongated particles should be less than about 25. In thisdiscussion, when we refer to elongated particles, we intend the term torefer to stiff, non-deformable particles having an aspect ratio of lessthan about 25. The elongated particles are preferably made from ceramicmaterials the same as or similar to those used in conventionalintermediate and high strength ceramic proppants. However, any materialmay be used that has the proper physical properties, in particularYoung's Modulus. Particularly suitable materials include ceramics suchas glass, bauxite ceramic, mullite ceramic, and metals such as aluminumand steels such as carbon steel, stainless steel, and other steelalloys.

Some suitable sizes for the elongated particles are as follows. If theparticles can be characterized most straightforwardly as cylinders orfibers (with the understanding that these and other characterizationsmay be approximations of the shapes and the actual shapes may beirregular), then the “lengths” may range from about 0.1 mm to about 30mm, and the “diameters” from about 0.1 mm to about 10 mm, preferablyfrom about 0.1 mm to about 3 mm. If the particles can be characterizedmost straightforwardly as disks or plates, then the “thickness” mayrange from about 10 microns to about 5000 microns and the “diameter” mayrange from about 0.5 mm to about 25 mm, or the “length” may range fromabout 1 mm to about 20 mm and the “width” may range from about 1 mm toabout 20 mm. The elongated particles may be used with any natural orsynthetic proppant or gravel. For rods (fibers) the ratio of thediameter of the elongated particle to the diameter of the conventional(spherical) proppant may range from about 0.1 to about 20; the preferredratio ranges from about 0.5 to about 3. For plates or disks, the ratioof the diameter of the conventional proppant to the thickness of theelongated particle may range from about 1 to about 100; the preferredratio is from about 4 to about 20; the optimal value is about 5. Forplates or disks, the ratio of the diameter of the conventional proppantto the thickness of the plate or disk may range from about 1 to about100; the preferred range is from about 3 to about 20; the optimal isabout 5. For plates or disks, the ratio of the length or width of theplate or disk to the diameter of the conventional proppant may rangefrom about 1 to about 50; the preferred range of the ratio is from about5 to about 10.

The most important feature of the elongated proppants is that they mustbe stiff, low-elasticity, and low-deformability materials. The Young'sModulus should be between about 0.02 and about 1100 GPa. Thedimensionless cross-sectional moment of inertia should be between about0.1 and 0.425. Particles having a low Young's Modulus will besufficiently stiff if they have a high enough ratio of dimensionlesscross sectional moment of inertia to dimensionless length (for examplerods with a large diameter and short length) although they still musthave a high enough aspect ratio to produce an increase in permeabilitydue to the wall effect.

An example of some suitable elongated particles is ceramic rods that arecomposed of at least about 92% alumina, at least about 2% silica, and atleast about 1% titanium. The rods have a diameter of about 0.85 to 0.90mm and a length of about 5-7 mm. They have a Young's Modulus of about160 GPa, a bending strength of about 300 MPa, a specific gravity ofabout 3.71 g/cm 3 and a roundness of about 0.9.

Another example is a solid rod-shaped particle prepared by sintering analumina-containing material, such as, for example, technical gradealumina, bauxite, or any other suitable combination of oxides thereof.The rod-shaped particle may have a solid trunk bounded by twosubstantially parallel planes. In one embodiment, the two substantiallyparallel planes may be substantially circular, thereby creating acylindrical trunk. Other suitable shapes may be also be used as thebounding planes. It is preferable that the bounding plane shapes have aminimum number of angles, such as circles or ovals or other symmetricalor asymmetrical shapes with rounded edges, such as egg curves, becauseangular particles tend to pack more tightly together and concentrate thepressure on the contact points between the particles because of theirsharp edges. This increased pressure can lead to an increased likelihoodthat the proppants will undesirably break into fine particles. Angularshapes, such as triangles, squares, rectangles, etc., where one or moreof the corners is rounded may also be used as the bounding planeswithout departing from the spirit of the present invention.

The sintered rod is found to exhibit superior hardness and toughness. Asknown in the art, increased alumina (Al₂O₃) content in the sinteredproduct results in increased hardness and toughness. Sintered rodsconsistent with one embodiment may have a high alumina content, forexample, greater than about 80% alumina by weight. In some embodiments,the alumina content may be increased to greater than about 90% byweight. It may further be preferable that the alumina content be greaterthan about 92% by weight, with the optimum hardness and toughness beingachieved between about 92% and about 96% alumina by weight.

It has also been found that the presence of aluminum titanate (Al₂TiO₅)in the sintered rod results in improved hardness and toughness. Thesintered rod may contain between about 0.2% and about 4% aluminumtitanate, preferably between about 0.5% and about 3%, and mostpreferably between about 1% and about 2.5%. In one embodiment, thealuminum titanate is formed during sintering when the pre-sinteredmaterial includes a small percentage of TiO₂. The TiO₂ may becontributed by non-bauxitic sources or, preferably, bauxite. In oneembodiment, the pre-sintered mixture may comprise by weight betweenabout 0.15% and about 3.5% TiO₂, preferably between about 0.3% and about2.7% TiO₂, and most preferably between about 0.4% and about 2.3% TiO₂.During the sintering process, which is preferably conducted at atemperature from 1300° C. to 1500° C., the TiO₂ forms a complex with thealumina to form the aluminum titanate phase.

The sintered rod may also be formulated to restrict its SiO₂ content toa specific low level (e.g., less than about 4% by weight, and preferablyno more than about 2% by weight). When the level is silica is greaterthan 4%, silica bridges the alumina crystals during the sintering stepand makes the ceramic material more fragile and breakable. By limitingthe SiO₂ content of the proppant, the sintered rod formulation ensuresoptimum strength from a high percentage of alumina (e.g., greater than92%) reinforced by the formation of aluminum titanate while at the sametime minimizing the weakening effects of SiO₂.

Examples of such solid rod-shaped particles are disclosed in patentapplication numbers US 20080053657, US 20080066910, US 20100087341 andUS 20100087342 all incorporated herewith by reference in their entirety.

In one embodiment, the elongated particles may be used withoutconventional proppant as the only proppant employed. In a secondembodiment, the elongated particles may also be mixed with conventionalproppant. At least a portion of a fracture may be packed with elongatedparticles and channelant particles. If the entire fracture is not packedwith elongated proppant, then the remaining part of the fracture may bepropped with conventional proppant or sand with channelant particles orwith a mixture of elongated and conventional proppant with channelantparticles. Such a mixture may vary from about 1 to about 99% elongatedproppant and may include more than one elongated proppant shape, length,diameter, and aspect ratio. For rods, the range is from about 20% toabout 100% by volume for fracturing or from about 50% to about 100%; forplates the range is from about 5% to about 50% by volume for fracturingor from about 5 to about 15%.

Mixtures of different sizes with the same shape as well as mixtures ofdifferent shapes and different sizes may be used. Improvements may beobtained from, for example, mixtures of plates and rods, and mixtures ofconventional proppants and plates and rods. Mixtures of different shapesmay increase flow back properties as well as provide additionalconductivity.

One embodiment of the proppant can use sand with an adhesive coatingalone, or an adhesive coating coated by a layer of non-adhesivesubstance dissolvable in the fracture as the fracture treatment fluid oranother fluid it passes through the fracture. A non-adhesive substanceinhibits the formation of proppant agglomerates prior to entering thefracture, and allows for control of a time moment in the fracture when,corresponding to a place where, a proppant particle gains its adhesiveproperties. The adhesive coating can be cured at the formationtemperature, and sand particles conglutinate between each other. Bondingparticles within the pillars can inhibit erosion of the proppant pillaras formation fluids flow past, and minimizes ultimate proppant islanddestruction by erosion.

In one embodiment, reinforcing and/or consolidating material can beintroduced into the fracture fluid to increase the strength of theproppant clusters formed and prevent their collapse during fractureclosure. Typically the reinforcement material can be added to theproppant substage and/or the mixed substage, but could also beintroduced additionally or alternatively in the channelant substageand/or the carrier substage, or in other ways. For example, thereinforcement material can be a fiber that serves to reinforce theproppant clusters, but can be removed as or with the channelant from theproppant-lean regions. The concentrations of both proppant and thereinforcing materials can vary in time throughout the proppant stage,and from substage to substage. That is, the concentration of proppantreinforcing material can be different at two subsequent substages. Itcan also be suitable in some applications of the present method tointroduce the reinforcing material in a continuous or semi-continuousfashion throughout the proppant stage, during a plurality of adjacentcarrier, channelant, mixed and proppant substages. For example, thereinforcing material deposited in the channelant regions in the fracturecan be removed with the channelant as described below. In any case,introduction of the reinforcing material need not be limited only to theproppant substage. Particularly, different implementations may be whenthe concentration of the reinforcing material does not vary during theentire proppant stage; monotonically increases during the proppantstage; or monotonically decreases during the proppant stage.

Curable or partially curable, resin-coated proppant can be used asreinforcing and consolidating material to form proppant clusters. Theselection process of the appropriate resin-coated proppant for aparticular bottom hole static temperature (BHST), and the particularfracturing fluid are well known to experienced workers. In addition,organic and/or inorganic fibers can reinforce the proppant cluster.These materials can be used in combination with resin-coated proppantsor separately. These fibers can have an inherently adhesive surface, canbe chemically or physically modified to have an adhesive coating, or canhave an adhesive coating resulting from a layer of non-adhesivesubstance dissolvable in the fracture by a fluid simultaneously orsubsequently passed through the fracture. Fibers made of adhesivematerial can be used as reinforcing material, coated by a non-adhesivesubstance that dissolves in the fracturing fluid or another fluid as itis passed through the fracture at the subterranean temperatures.Metallic particles are another embodiment for reinforcing material andcan be produced using aluminum, steel optionally containing specialadditives that inhibit corrosion, and other metals and alloys, and thelike. The metallic particles can be shaped to resemble a sphere andmeasure 0.1-4 mm, for example. In one embodiment, metallic particles canhave an elongated shape with a length longer than 2 mm and a diameter of10 to 200 microns. In another embodiment, plates of organic or inorganicsubstances, ceramics, metals or metal-based alloys can be used asreinforcing material in the proppant. These plates can be disk orrectangle-shaped and of a length and width such that for all materialsthe ratio between any two of the three dimensions is greater than 5 to1.

Alternatively, a high permeability and/or high porosity proppant packcan be suitably employed without detriment. In one embodiment, thepermeability of the proppant can provide some limited fractureconductivity in the event the channels are not properly formed or do notfully interconnect. Additionally, under some formation conditions it canbe advantageous when using the present method to perform a final tail-instage of the fracturing treatment involving continuous proppantintroduction into the fracturing fluid, with the proppant at this stageconsisting essentially of uniform particle size to obtain a zone ofcontinuous-porosity proppant adjacent to the wellbore. If employed, thetail-in stage of the fracturing treatment resembles a conventionalfracturing treatment, where a continuous bed of well-sorted conventionalproppant is placed in the fracture relatively near to the wellbore. Thetail-in stage can involve introduction of both an agent that increasesthe proppant transport capability of the treatment fluid and/or an agentthat acts as a reinforcing material. The tail-in stage is distinguishedfrom the second stage by the continuous placement of a well-sortedproppant, that is, a proppant with an essentially uniform particle size.The proppant strength is sufficient to prevent its cracking (crumbling)when subjected to stresses that occur at fracture closure. The role ofthe proppant at this tail stage is to prevent fracture closure and,therefore, to provide good fracture conductivity in proximity to thewellbore.

The proppants useful in the present method must also be capable of beingsegregated into proppant-rich islands for heterogeneous placement in thefracture spaced away from adjacent proppant islands. Properties such asdensity, size, shape, magnetic characteristics, surface characteristics,for example, hydroaffinity and reactivity, and chemical or mechanicalinteraction with the channelant, and the like, can all influence thesegregability of the proppant. Therefore, these characteristics can beselected to facilitate segregation from the channelant-rich regionsdepending on the manner in which segregation is effected, downholeconditions, the channelant, the treatment fluid, etc.

In an embodiment, the proppant can have a self-adherent surface, forexample, by using a proppant that has a natural attraction for or atendency to agglomerate with or adhere to other proppant particles,and/or by coating or chemically modifying the surface of the proppantfor self-adhesion, e.g. by coating the proppant with an adhesive ortackifier, or grafting an adhesive or tackifying compound to theproppant. Preferably, the self-adherent proppant is non-adherent to thechannelant and other surfaces such as the surface piping, pumps andwellbore tubing. In one version of the self-adherent proppant, theproppant is loosely held together in cohesive slugs or globules of a gelor lightly crosslinked, flowable polymer for which the proppant has adifferential affinity, e.g. the proppant can be grafted to thegel-forming polymer.

In one embodiment, the proppant can be hydrophilic, for example, byusing a proppant that is normally hydrophilic, such as most sand, forexample, and/or by treating the proppant particles with ionic or polarmodifiers such as a strong acid, weak acid, strong base, weak base, orreacting the surface of the proppant to associate an ionic or polarmoiety with an affinity to aqueous liquids. In this manner, the proppantcan be differentially attracted to other hydrophilic species in thetreatment fluid, e.g. other proppant particles or an immiscible fluidphase in the treatment fluid, such as an aqueous phase, especially wherethe channelant is hydrophobic and/or introduced via an immisciblehydrophobic fluid phase in the treatment fluid.

In another embodiment, the proppant can be rendered hydrophobic, forexample, by using proppant that is normally hydrophobic, such as wax,for example, and/or by treating the proppant particles with an oil, waxor other hydrocarbon, or reacting the surface of the proppant toassociate a hydrocarbyl moiety with a low affinity to aqueous liquids.In this manner, the proppant can be differentially attracted to otherhydrophobic species in the treatment fluid, e.g. other proppantparticles or an immiscible fluid phase in the treatment fluid, such asan oil or other non-aqueous phase, especially where the channelant ishydrophilic and/or introduced via an immiscible hydrophilic fluid phasein the treatment fluid.

In one embodiment the proppant can be present in the treatment fluidthat is injected into the fracture in the form of an immiscible fluidpacket or globule dispersed in a more or less continuous phase of asecond fluid carrying the channelant. The immiscible fluid proppantpackets can each contain sufficient proppant to form a suitably sizedisland, singly from isolated packet placement or in combination with oneor more additional proppant packets where cumulative packet placementcan occur. Because the open channels to be formed must interconnectbetween the wellbore and the remote exposed surfaces in the fracture, itcan be convenient to provide the channelant in a continuous phase in thetreatment fluid in which the proppant packets are a dispersed ordiscontinuous phase. In one version, the proppant packets can beprovided with a thin encapsulating skin or deformable bladder to retainthe proppant and remain flowable during injection, and the bladder canbe optionally ruptured or chemically or thermally removed duringplacement in the fracture and/or during closure of the fracture.

The choice of channelant can depend on the mode of channelantsegregation and placement in the fracture, as well as the mode ofchannelant removal and channel formation. In its simplest form, thechannelant can be a solid particulate that can be maintained in itssolid form during injection and fracture closure, and readily dissolvedor degraded for removal. Materials that can be used can be organic,inorganic, glass, ceramic, nylon, carbon, metallic, and so on. Suitablematerials can include water- or hydrocarbon-soluble solids such as, forexample, salt, calcium carbonate, wax, or the like. Polymers can be usedin another embodiment, including polymers such as , polylactic acid(PLA), polyglycolic acid (PGA), polyol, polyethylene terephthalate(PET), polysaccharide, wax, salt, calcium carbonate, benzoic acid,naphthalene based materials, magnesium oxide, sodium bicarbonate,soluble resins, sodium chloride, calcium chloride, ammonium sulfate, andthe like, and so on, or any combinations thereof. As used herein,“polymers” includes both homopolymers and copolymers of the indicatedmonomer with one or more comonomers, including graft, block and randomcopolymers. The polymers can be linear, branched, star, crosslinked,derivitized, and so on, as desired. The channelant can be selected tohave a size and shape similar or dissimilar to the size and shape of theproppant particles as needed to facilitate segregation from theproppant. Channelant particle shapes can include, for example, spheres,rods, platelets, ribbons, and the like and combinations thereof. In someapplications, bundles of fibers, or fibrous or deformable materials, canbe used. These fibers can additionally or alternatively form athree-dimensional network, reinforcing the proppant and limiting itsflowback.

For example, the separation of injected proppant blend and channelant asintroduced and placed in the fracture can be induced by differences (orsimilarities) in size, density or shape of the two materials. Thespecific gravities and the volume concentrations of proppant blend andchannelant can be tailored to minimize mixing and homogenization duringplacement. Properly sizing the channelant or adding various weightingagents to the channelant-rich fluid can facilitate segregation at theappropriate time and location.

Either the proppant or the proppant-spacing particles can also be madeto be “sticky”, so particles of similar material adhere to one another,helping ensure heterogeneity between the two dissimilar materials.Proppant particles can be selected that adhere to other proppantparticles as discussed above and to be repelled by or repel thechannelant particles. Alternatively, or additionally, channelantparticles can be selected that are self-adherent and non-adherent to theproppant. The channelant can, for example, include a self-adherentcoating. Another technique to encourage separation of the two materialsis selecting proppant and channelant with inherent hydroaffinitydifferences, or creating surface hydroaffinity differences by treatingeither the proppant or the channelant with hydrophobic or hydrophiliccoatings.

The presence of the channelant in the fracturing fluid in the proppantstage, e.g. in a mixed substage or in a segregated channelant substage,can have the benefit of increasing the proppant transport capability. Inother words, the channelant can reduce the settling rate of proppant inthe fracture treatment fluid. The channelant can in an embodiment be amaterial with elongated particles having a length that much exceeds adiameter. This material can affect the rheological properties andsuppress convection in the fluid, which can result in a decrease of theproppant settling rate in the fracture fluid and maintain segregation ofthe proppant from proppant lean regions. The channelant can be capableof decomposing in the water-based fracturing fluid or in the downholefluid, such as fibers made on the basis of polylactic acid (PLA),polyglycolic acid (PGA), polyvinyl alcohol (PVOH), and others. Thefibers can be made of or coated by a material that becomes adhesive atsubterranean formation temperatures. They can be made of adhesivematerial coated by a non-adhesive substance that dissolves in thefracturing fluid or another fluid as it is passed through the fracture.The fibers used in one embodiment can be up to 2 mm long with a diameterof 10-200 microns, in accordance with the main condition that the ratiobetween any two of the three dimensions be greater than 5 to 1. Inanother embodiment, the fibers can have a length greater than 1 mm, suchas, for example, 1-30 mm, 2-25 mm or 3-18 mm, e.g. about 6 mm; and theycan have a diameter of 5-100 microns and/or a denier of about 0.1-20,preferably about 0.15-6. These fibers are desired to facilitate proppantcarrying capability of the treatment fluid with reduced levels of fluidviscosifying polymers or surfactants. Fiber cross-sections need not becircular and fibers need not be straight. If fibrillated fibers areused, the diameters of the individual fibrils can be much smaller thanthe aforementioned fiber diameters.

The concentration of the channelant in the treatment fluid canconveniently be such that the channelant compressed between the proppantislands by fracture closure has a packed volume to fill the spacesbetween the packed proppant islands with similar stress in both theproppant and channelant. In other words, the channelant fill serves tohold the proppant islands in place and inhibit lateral expansion thatwould otherwise reduce the ultimate height of the proppant pillar. Theweight concentration of the fibrous channelant material in thefracturing fluid can be from 0.1 to 10 percent in one embodiment. Theconcentration of the solid channelant material in the treatment fluid inanother embodiment is typically from about 0.6 g/L (about 5 ppt) toabout 9.6 g/L (about 80 ppt).

In an embodiment, a first type of fiber additive can providereinforcement and consolidation of the proppant. This fiber type caninclude, for example, glass, ceramics, carbon and carbon-basedcompounds, metals and metallic alloys, and the like and combinationsthereof, as a material that is packed in the proppant to strengthen theproppant pillars. In other applications, a second type of fiber can beused that inhibits settling of the proppant in the treatment fluid. Thesecond fiber type can include, for example, polylactic acid,polyglycolic acid, polyethylterephthalate (PET), polyol, and the likeand combinations thereof, as a material that inhibits settling ordispersion of the proppant in the treatment fluid and serves as aprimary removable fill material in the spaces between the pillars. Yetother applications include a mixture of the first and second fibertypes, the first fiber type providing reinforcement and consolidation ofthe proppant and the second fiber type inhibiting settling of theproppant in the treatment fluid.

The fibers can be hydrophilic or hydrophobic in nature. Hydrophilicfibers are preferred in one embodiment. Fibers can be any fibrousmaterial, such as, but not necessarily limited to, natural organicfibers, comminuted plant materials, synthetic polymer fibers (bynon-limiting example polyester, polyaramide, polyamide, novoloid or anovoloid-type polymer), fibrillated synthetic organic fibers, ceramicfibers, inorganic fibers, metal fibers, metal filaments, carbon fibers,glass fibers, ceramic fibers, natural polymer fibers, and any mixturesthereof. Particularly useful fibers are polyester fibers coated to behighly hydrophilic, such as, but not limited to, DACRON® polyethyleneterephthalate (PET) Fibers available from Invista Corp. Wichita, Kans.,USA, 67220. Other examples of useful fibers include, but are not limitedto, polylactic acid polyester fibers, polyglycolic acid polyesterfibers, polyvinyl alcohol fibers, and the like.

In an embodiment, the solid channelant material is selected fromsubstituted and unsubstituted lactide, glycolide, polylactic acid,polyglycolic acid, copolymers of polylactic acid and polyglycolic acid,copolymers of glycolic acid with other hydroxy-, carboxylic acid-, orhydroxycarboxylic acid-containing moieties, copolymers of lactic acidwith other hydroxy-, carboxylic acid-, or hydroxycarboxylicacid-containing moieties, and mixtures of such materials. Preferredexamples are polyglycolic acid or PGA, and polylactic acid or PLA. Thesematerials function as solid-acid precursors, and upon dissolution in thefracture, can form acid species which can have secondary functions inthe fracture.

If desired, a pH control agent can be used in the treatment fluid,especially where a solid acid precursor is present and one or more ofthe other treatment fluids is pH-sensitive. The pH control agent can beselected from amines and alkaline earth, ammonium and alkali metal saltsof sesquicarbonates, carbonates, oxalates, hydroxides, oxides,bicarbonates, and organic carboxylates, for example sodiumsesquicarbonate, triethanolamine, or tetraethylenepentamine.

For example, the channelant can function as an acid breaker for aviscosifying agent, where the channelant is selected from a solid thatcontains an acid and that hydrolyzes to release an acid, a solid thathydrolyzes to release an acid, and mixtures of such materials. The solidcan be present in particles sufficiently small that they at leastpartially enter pores of the formation, and/or sufficiently large thatthey remain in the fracture in the spaces between the proppant pillars.The treatment fluid can also contain a pH control agent present in anamount sufficient to neutralize any acid present in the solid materialbefore the injection and to neutralize any acid generated by the solidmaterial during the injection, so that the acid breaker is not availableto break the fluid during the injection. When the injection is stopped,the solid is allowed to release acid in excess of the amount that can beneutralized by any pH control agent, thereby breaking the viscous fluid.Optionally, the viscosifying agent in this embodiment is a viscoelasticsurfactant system. Optionally, the solid material is of a size thatforms an internal filter cake in the pores of the formation. Optionally,the solid material is of a size that does not block the flow of fluid inthe pores of the formation. The solid material is selected fromsubstituted and unsubstituted lactide, glycolide, polylactic acid,polyglycolic acid, copolymers of polylactic acid and polyglycolic acid,copolymers of glycolic acid with other hydroxy-, carboxylic acid-, orhydroxycarboxylic acid-containing moieties, copolymers of lactic acidwith other hydroxy-, carboxylic acid-, or hydroxycarboxylicacid-containing moieties, and mixtures of such materials. One example ispolyglycolic acid. The pH control agent is selected from amines andalkaline earth, ammonium and alkali metal salts of sesquicarbonates,carbonates, oxalates, hydroxides, oxides, bicarbonates, and organiccarboxylates, for example sodium sesquicarbonate, triethanolamine, ortetraethylenepentamine.

Suitable solid acids for use in viscoelastic surfactant (VES) fluidsystems include substituted and unsubstituted lactide, glycolide,polylactic acid, polyglycolic acid, a copolymer of polylactic acid andpolyglycolic acid, a copolymer of glycolic acid with other hydroxy-,carboxylic acid-, or hydroxycarboxylic acid-containing moieties, acopolymer of lactic acid with other hydroxy-, carboxylic acid orhydroxycarboxylic acid-containing moieties, or mixtures of thepreceding. Other materials suitable for use in VES fluid systems are allthose polymers of hydroxyacetic acid (glycolic acid) with itself orother hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containingmoieties described in U.S. Pat. Nos. 4,848,467; 4,957,165; and4,986,355, all three hereby incorporated by reference. Suitable solidacids are also described in U. S. Patent Application Publication Nos.2003/002195 and 2004/0152601, both of which are hereby incorporated byreference and are assigned to the assignee of the present application.

Excellent solid acid components for VES systems are solid cyclic dimers,or solid polymers, of certain organic acids, that hydrolyze under knownand controllable conditions of temperature, time and pH to form organicacids. One example, a suitable solid acid is the solid cyclic dimer oflactic acid known as “lactide”, which has a melting point of 95 to 125°C. depending upon the optical activity. Another is a polymer of lacticacid, sometimes called a polylactic acid or “PLA”, or a polylactate, ora polylactide. Another example is the solid cyclic dimer of gylycolicacid known as “glycolide”, which has a melting point of about 86° C. Yetanother example is a polymer of glycolic acid (hydroxyacetic acid), alsoknown as polyglycolic acid (“PGA”), or polyglycolide. Another example isa copolymer of lactic acid and glycolic acid. These polymers andcopolymers are polyesters. The as-received materials can contain somefree acid and some solvent, typically water.

Natureworks L.L.C., Minnetonka, Minn., USA, produces the solid cycliclactic acid dimer called “lactide” and from it produces lactic acidpolymers, or polylactates, with varying molecular weights and degrees ofcrystallinity, under the generic trade name NATUREWORKS™ PLA. The PLA'scurrently available from Cargill Dow have molecular weights of up toabout 100,000, although any polylactide (made by any process by anymanufacturer) and any molecular weight material of any degree ofcrystallinity can be used in the embodiments of the Invention. The PLApolymers are solids at room temperature and are hydrolyzed by water toform lactic acid. Those available from Cargill Dow typically havecrystalline melt temperatures of from about 120 to about 170° C., butothers are obtainable. Poly(d,l-lactide) is available from Bio-Invigor,Beijing and Taiwan, with molecular weights of up to 500,000. Bio-Invigoralso supplies polyglycolic acid (also known as polyglycolide) andvarious copolymers of lactic acid and glycolic acid, often called“polyglactin” or poly(lactide-co-glycolide). The rates of the hydrolysisreactions of all these materials are governed, among other factors, bythe molecular weight, the crystallinity (the ratio of crystalline toamorphous material), the physical form (size and shape of the solid),and in the case of polylactide, the amounts of the two optical isomers.(The naturally occurring l-lactide forms partially crystalline polymers;synthetic dl-lactide forms amorphous polymers.) Amorphous regions aremore susceptible to hydrolysis than crystalline regions. Lower molecularweight, less crystallinity and greater surface-to-mass ratio all resultin faster hydrolysis. Hydrolysis is accelerated by increasing thetemperature, by adding acid or base, or by adding a material that reactswith the hydrolysis product(s).

Homopolymers of PGA and PLA can be more crystalline; copolymers tend tobe amorphous unless they are block copolymers. The extent of thecrystallinity can be controlled by the manufacturing method forhomopolymers and by the manufacturing method and the ratio anddistribution of lactide and glycolide for the copolymers. Polyglycolidecan be made in a porous form. Some of the polymers dissolve very slowlyin water before they hydrolyze; it is to be understood that the termshydrolyze or hydrolysis, etc., are intended to include dissolution.

The solid acids can be coated to slow the hydrolysis. Suitable coatingsinclude polycaprolate (a copolymer of glycolide andepsilon-caprolactone), and calcium stearate, both of which arehydrophobic. Polycaprolate itself slowly hydrolyzes. Generating ahydrophobic layer on the surface of the solid acids by any means canfacilitate segregation from hydrophilic proppant and can delay thehydrolysis for injection and fracture. Note that coating here can referto encapsulation or simply to changing the surface by chemical reactionor by forming or adding a thin film of another material. Anothersuitable method of delaying the hydrolysis of the solid acid, and therelease of acid, is to suspend the solid acid, optionally with ahydrophobic coating, in an oil or in the oil phase of an emulsion. Thehydrolysis and acid release do not occur until water contacts the solidacid.

The VES self-destructs in situ, that is, in the location where it isplaced. That location can be part of a suspension in a treatment fluidin the wellbore, in perforations, in a gravel pack, or in a fracture; oras a component of a filter cake on the walls of a wellbore or of afracture; or in the pores of a formation itself. The VES can be used informations of any lithology but are used most commonly in carbonates orsandstones.

A particular advantage of these materials is that the solid acidprecursors and the generated acids are non-toxic and are biodegradable.The solid acids are often used as self-dissolving sutures in medicalpractice, for example.

A polyol is a polyhydric alcohol, i.e., one containing three or morehydroxyl groups. One embodiment of a polyol useful as a channelant is apolymeric polyol solubilizable upon heating, desalination or acombination thereof, and which consists essentially ofhydroxyl-substituted carbon atoms, in a polymer chain, spaced fromadjacent hydroxyl-substituted carbon atoms by at least one carbon atomin the polymer chain. In other words, the useful polyols are preferablyessentially free of adjacent hydroxyl substituents. In one embodiment,the polyol has a weight average molecular weight greater than 5000 up to500,000 or more, and from 10,000 to 200,000 in another embodiment. Thepolyol can if desired be hydrophobically modified to further inhibit ordelay solubilization, e.g. by including hydrocarbyl substituents such asalkyl, aryl, alkaryl or aralkyl moieties and/or side chains having from2 to 30 carbon atoms. The polyol can also be modified to includecarboxylic acid, thiol, paraffin, silane, sulfuric acid, acetoacetylate,polyethylene oxide, or quaternary amine or other cationic monomers. Suchmodifications have several affects on the properties of the polyol;affects on solubility, sensitivity to salinity, pH, and crosslinkingfunctionalities (e.g. hydroxyl groups and silanol groups which arechelates that can crosslink with common crosslinkers) are of mostinterest to the present invention. All of said modifications arecommercially available products.

In one embodiment, the polyol is a substituted or unsubstitutedpolyvinyl alcohol that can be prepared by at least partial hydrolysis ofa precursor polyvinyl compound having ester substituents, such as, forexample, polyvinyl acetate, polyvinyl propanoate, polyvinyl butanoate,polyvinyl pentanoate, polyvinyl hexanoate, polyvinyl 2-methyl butanoate,polyvinyl 3-ethylpentanoate, polyvinyl 3-ethylhexanoate, and the like,and combinations thereof. When the polyol comprises polyvinyl alcoholprepared by at least partial hydrolysis of polyvinyl acetate, the polyolis not generally soluble in salt water, as discussed in more detailbelow, and further, the polyol is commercially available in the form ofpartially crystalline fibers that have a relatively sharp triggertemperature below which the fibers are not soluble in water and abovewhich they readily dissolve.

The methods described herewith may be used in a well where at least partof the well is horizontal. In one embodiment, when elongated particlesare mixed with conventional proppant in the particulate blend, not bebound by a theory it is believed stability of the proppant clustersforming pillars will be improved. Interaction of the elongatedparticles, optionally with the fibers, with the conventional proppantallow better fluid flow through the pillars and channelant.

The foregoing disclosure and description of the invention isillustrative and explanatory thereof and it can be readily appreciatedby those skilled in the art that various changes in the size, shape andmaterials, as well as in the details of the illustrated construction orcombinations of the elements described herein can be made withoutdeparting from the spirit of the invention.

1. A method of placing a proppant pack into a fracture formed in asubterranean formation, the method comprising: injecting well treatmentfluid comprising proppant and channelant through a wellbore into afracture in a subterranean formation, wherein the proppant comprisesfrom 1 to 100 percent in weight of stiff, low-elasticity andlow-deformability elongated particles; placing the proppant in thefracture in a plurality of proppant clusters forming pillars spacedapart by the channelant; and, removing the channelant to form openchannels around the pillars for fluid flow from the formation throughthe fracture toward the wellbore.
 2. The method of claim 1, wherein theelongated particles have a maximal cross-sectional dimension, h1, and aminimal cross-sectional dimension, h2, of from 0.1 to 10 mm; a length,L, of from 0.1 to 20 mm; for 1D particles, a ratio L/h1 from 1.2 to 10and a ratio h2/h1 from 0.8 to 1; for 2D particles, a ratio L/h1 from 1to 1.19 and a ratio h2/h1 from 0.1 to 0.79; a curvature, χ, of from 0 to2/h2 in units of 1/mm; for 1D particles, a stiffness, k, of from 0 to4.90*10⁸ in units of N*mm²; and for cylindrical particles, a stiffness,k, of from 0 to 10⁸ N*mm²; a range of a particle unevenness d0 (or d1)is from 0 to 0.5*h1 in units of mm.
 3. The method of claim 2, whereinthe elongated particles comprise a mixture of elongated particlesdiffering from one another in at least one parameter selected from thegroup consisting of length, a cross-sectional dimension, density,curvature, and stiffness.
 4. The method of claim 1 wherein thechannelant comprises solid particles.
 5. The method of claim 4comprising segregating the proppant and channelant during injection ofthe well treatment fluid.
 6. The method of claim 4 wherein thechannelant particles are maintained in a solid state within thefracture.
 7. The method of claim 1 wherein the injection comprises:injecting a proppant-lean carrier stage to initiate the fracture; andthereafter injecting into the fracture proppant and channelant.
 8. Themethod of claim 1, wherein the injection further comprises injecting atail-in stage to form a permeable proppant pack in the fracture betweenthe open channels and the wellbore.
 9. The method of claim 1 wherein thetreatment fluid comprises mixed phases including a proppant-rich phasewith elongated particles from 1 to 100 percent in weight and achannelant-rich phase.
 10. The method of claim 1 wherein the treatmentfluid comprises alternating volumes of proppant-rich fluid withelongated particles from 1 to 100 percent in weight separated by volumescontaining the channelant.
 11. The method of claim 1 wherein thetreatment fluid comprises alternating volumes of proppant-rich fluidwithout elongated particles separated by volumes containing thechannelant.
 12. The method of claim 1 wherein the treatment fluidcomprises a mixture of the proppant with elongated particles from 1 to100 percent in weight and channelant, further comprising segregating theproppant and channelant for the fracture placement.
 13. The method ofclaim 1 wherein the channelant comprises a solid acid-precursor togenerate acid in the fracture.
 14. The method of claim 13 wherein thegenerated acid etches surfaces of the formation to enlarge the openchannels.
 15. The method of claim 1 wherein the channelant particles areselected from the group consisting of polylactic acid (PLA),polyglycolic acid (PGA), polyol, salt, polysaccharide, wax, calciumcarbonate, benzoic acid, naphthalene based materials, magnesium oxide,sodium bicarbonate, soluble resins, polyvinyl alcohol (PVOH) andcombinations thereof.
 16. The method of claim 1 wherein the channelantcomprises a fluoride source.
 17. The method of claim 1, furthercomprising producing fluids from the formation through the open channelsand the wellbore.
 18. The method of claim 1, wherein the treatment fluidfurther comprises fibers.
 19. The method of claim 18 wherein the fibersare selected from the group consisting of glass, ceramics, carbon andcarbon-based compounds, metals and metallic alloys, polylactic acid,polyglycolic acid, polyethylene terephthalate, polyol and combinationsthereof.
 20. The method of claim 18 wherein the fibers comprise amixture of first and second fiber types, the first fiber type providingreinforcement and consolidation of the proppant and the second fibertype inhibiting settling of the proppant in the treatment fluid.
 21. Themethod of claim 20 wherein the first fiber type is selected from thegroup consisting of glass, ceramics, carbon and carbon-based compounds,metals and metallic alloys, and combinations thereof, and the secondfiber type is selected from the group consisting of polylactic acid,polyglycolic acid, polyethylterephthalate (PET), polyol and combinationsthereof
 22. The method of claim 18 wherein the fibers comprise athermoplastic coating able to interact with at least part of theproppant to provide reinforcement and consolidation of the proppant orto inhibit settling of the proppant or to retard movement of theproppant within the subterranean formation.
 23. The method of claim 1,wherein the subterranean formation comprises at least in part shalerock.
 24. A method of placing a proppant pack into a fracture formed ina subterranean formation, the method comprising: injecting welltreatment fluid comprising elastic and deformable material, proppant andchannelant through a wellbore into a fracture in a subterraneanformation, wherein the proppant comprises from 1 to 100 percent inweight of stiff, low-elasticity and low-deformability elongatedparticles; placing the proppant in the fracture in a plurality ofproppant clusters forming pillars spaced apart by the channelant; and,removing the channelant to form open channels around the pillars forfluid flow from the formation through the fracture toward the wellbore.25. The method of claim 24, wherein the elongated particles have amaximal cross-sectional dimension, h1, and a minimal cross-sectionaldimension, h2, of from 0.1 to 10 mm; a length, L, of from 0.1 to 20 mm;for 1D particles, a ratio L/h1 from 1.2 to 10 and a ratio h2/h1 from 0.8to 1; for 2D particles, a ratio L/h1 from 1 to 1.19 and a ratio h2/h1from 0.1 to 0.79; a curvature, χ, of from 0 to 2/h2 in units of 1/mm;for 1D particles, a stiffness, k, of from 0 to 4.90*10⁸ in units ofN*mm²; and for cylindrical particles, a stiffness, k, of from 0 to 10⁸N*mm²; a range of a particle unevenness d0 (or d1) is from 0 to 0.5*h1in units of mm.
 26. The method of claim 25, wherein the elongatedparticles comprise a mixture of elongated particles differing from oneanother in at least one parameter selected from the group consisting oflength, a cross-sectional dimension, density, curvature, and stiffness.27. The method of claim 24, wherein the deformable and elastic materialis rod, oval, plate, disk, sphere, platelet, particle, fiber or ribbon.28. The method of claim 24, wherein the deformable and elastic materialis a thermoplastic polymer.
 29. The method of claim 28, wherein thedeformable and elastic material is a coating on another material notnecessarily made of deformable and elastic material.
 30. The method ofclaim 28, wherein the thermoplastic polymer comprises at least onemember selected from the group of polyolefins, polyamides, polyvinyls,polyimides, polyurethanes, polysulfones, polycarbonates, polyesters andcellulose derivatives.
 31. The method of claim 24, wherein thedeformable and elastic material is able to interact with at least partof the proppant to provide reinforcement and consolidation of theproppant or to inhibit settling of the proppant or to retard movement ofthe proppant within the subterranean formation.
 32. A method of placinga proppant pack into a fracture formed in a subterranean formation, themethod comprising: injecting well treatment fluid comprising proppantand channelant through a wellbore into a fracture in a subterraneanformation, wherein the proppant comprises from 1 to 100 percent inweight of stiff, low-elasticity and low-deformability particles having ashape with a length basis aspect ratio greater than 5; placing theproppant in the fracture in a plurality of proppant clusters formingpillars spaced apart by the channelant; and, removing the channelant toform open channels around the pillars for fluid flow from the formationthrough the fracture toward the wellbore.
 33. The method of claim 1,wherein the subterranean formation comprises at least in part shalerock.
 34. The method of claim 1, wherein the treatment is done in a welland at least a part of the well is horizontal.
 35. A method of placing aproppant pack into a fracture formed in a subterranean formation of awell, wherein the subterranean formation comprises at least in partshale rock and wherein at least a part of the well is horizontal, themethod comprising: injecting well treatment fluid comprising proppantand channelant through a wellbore into a fracture in a subterraneanformation, wherein the proppant comprises from 1 to 100 percent inweight of stiff, low-elasticity and low-deformability elongatedparticles; placing the proppant in the fracture in a plurality ofproppant clusters forming pillars spaced apart by the channelant; and,removing the channelant to form open channels around the pillars forfluid flow from the formation through the fracture toward the wellbore.